Tie-back system for underwater completion

ABSTRACT

The tie-back collar of an inner casing is provided with a protector sleeve which is sealed in place and supported against rotation. To temporarily abandon the well after the annulus between the inner and an outer string has been fully cemented up past the tie-back collar, the inner and outer strings are severed with a casing cutter above the tie-back collar. When tying back into the well, a spear may be used to retrieve the remaining part of the protector and a thread-in or stab-in tie-back sub may then be connected to the inner string to reestablish communication with the well.

United States Patent Holbert, Jr.

[54] TIE-BACK SYSTEM FOR UNDERWATER COMPLETION [72] Inventor: Marvin L.Holbert, Jr., Houston, Tex.

[73] Assignee: Gray Tool Company, Houston, Tex.

[22] Filed: Mar. 23, 1970 211 App1.No.: 21,980

[52] U.S.CI ..166/297, l66/.5, 166/85, 285/18 [51] Int. Cl. ..E2lb 29/00[58] FieldolSear ch ..166/.5,226,315,75, 77.5, 166/85, 297, 298; 285/18,133 A, 133 R [56] References Cited UNITED STATES PATENTS 3,287,03011/1966 Crain et a]. ..285/18 3,3l0,107 3/1967 Yancey 166/85 51 May 23,1972 Primary Examiner-James A. Leppink Anomey-Cushman, Darby & CushmanABSTRACT The tie-back collar of an inner casing is provided with aprotector sleeve which is sealed in place and supported againstrotation. To temporarily abandon the well after the annulus between theinner and an outer string has been fully cemented up past the tie-backcollar, the inner and outer strings are severed with a casing cutterabove the tie-back collar. When tying back into the well, a spear may beused to retrieve the remaining part of the protector and a thread-in orstab-in tieback sub may then be connected to the inner string toreestablish communication with the well.

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\ ATTORN/LYS PATENTED m 2 3 1912 IJIHEI 6 UF 7 M ATTORNEYS NNNQ y yBACKGROUND OF THE INVENTION The U.S. Pat. of Pitts et al, No. 3,405,763,issued Oct. 15, 1968 describes a down-hole, pawl-tripped, expansiblen'ngtype casing hanging system substantially as sold by the assignee ofthat patent, Gray Tool Company of Houston, Tex. as its DJ line of wellcompletion equipment. (See pages 2104-2107 of Composite'Catalog ofOilfield Equipment and Services, 1968-69 Edition, Gulf Publishing Co.,Houston, Tex.) That well completion apparatus is fairly explicitlydescribed in those publically available documents and so will not bedescribed in such detail here. Suffice it to say here drawing particularattention to FIG. 9b of the Pitts et al patent that the system providesfor hanging an inner string of pipe with respect to an outer string ofpipe by means of incorporation of a fluted hanger in the inner string,which seats on a downhole internal shoulder in the bore of the outerstring via a bearing ring which is initially stowed in an inactive modeon the hangenthen released for self-expansion through themtion of apawl-tripping arrangement.

One feature of the DJ equipment which-has found acceptance in themarketplace is the provision of an unscrewable joint at the upper end ofthe hanger, which is for allowing easy recovery of all of the innerstring, above the hanger even after cementing, should temporaryabandonment and capping of the well be found desirable.

(Temporary abandonment is utilized in the petroleum well drillingindustry to permit maximum use of equipment during the period ofdrilling of exploration and field or formation definition wells, beforea decision has been reached whether there is enough recoverablesubterranean petroleum and attendant products to make completion,production, separation and gathering economically feasible.) When adecision is made to complete the abandoned well a threaded or stabbablesub is reconnected to the hanger. This procedure is described in thePitts et al patent in relation to FIGS. 10-12 thereof. Additionaldesigns of tie-back subs usable with the DJ hangers are illustrated inthe U.S. Pats. of Quebe et al, No. 3,400,950, issued Sept. 10, 1968 andHarwell, Jr., U.S. Pat. No. 3,456,729, issued July 22, 1969, bothassigned to Gray Tool Company.

The unscrewable joint referred to above also comes into use duringcementing of the inter-string annulus since circulating parts forwashing out excess cement are provided on the hanger. These may beexposed by partly unthreading the sub from the hanger at saidunscrewable joint.

In the cementing operation, cement is forced down the bore of the innerstring with a following plug until returns from the inter-casing annulusare visible at the surface (i.e. issue from piping connected to thatannulus at the surface). Then the circulation parts are opened andwashing fluid is circulated out the ports and up to the surface for asufficient period of time (e.g. 2 hours) that the washing fluid is nolonger turbid with diluted cement, indicating that the cement in theannulus has been washed out down to the level of the circulating portsand probably to a level somewhat therebelow. However with methodscurrently in use by most operators it cannot be known with certaintythat some cement has not been left above the desired level due tochanneling of the washing fluid through the cement. If such cement isleft and is allowed to harden, the tie-back sub may be locked in placeso it can neither be backed out nor fully reconnected.

In the U.S. Patent application of John Slack and Willis Marvin Phipps,Ser. No. 876,809, filed Nov. 14, 1969, there is disclosed a tie-backconnection including a sub, spaced further above (for instance 6-25 feetabove) the hanger. After an inter-casing string annulus has beencemented to a level above a down hole hanger in the inner string, a subis partly backed out of an upward extension of the hanger to exposecirculating ports having conduits channeling washing fluid tosubstantially below the sub-to-hanger connection and preferably to thelevel of the hanger flutes, to provide for disconnection andreconnection of the sub (for temporary abandonment of the well) and forcutting the inner casing below its hang point (for recovery of thestring in a permanent'abandonment of the well). In one embodiment thewashing fluid conduits are individual pipes; in another, they include asingle tube surrounding an-upward extension of the hanger.

However, there are instances where, due to governmental regulations,operator predilection or upon the recommendation of petroleumgeologists, full cementing of certain inner/outer casing string annuliis employed.

SUMMARY OF THE INVENTION The present invention provides ways and meansfor providing permanent or temporary abandonment with provision forsubsequent tie-back and completion) of particularly, but notexclusively, underwater petroleum wells.

In making use of the invention the tie-back collar of an inner casing isprovided with a protector sleeve which is sealed in place and supportedagainst rotation. To temporarily abandon the well after the annulusbetween the inner and an outer string has been fully cemented up pastthe tie-back collar, the inner and outer strings are severed with acasing cutter above the tie-back collar. When tying back into the well,a spear may be used to retrieve the remaining part of the protector anda thread-in or stab-in tie-back sub may then be connected to the innerstring to reestablish communication with the well.

The principles of the invention will be further hereinafter discussedwith reference to the drawings wherein preferred embodiments are shown.The specifics illustrated in the drawings are intended to exemplify,rather than limit, aspects of the invention as defined in the claims.

BRIEF DESCRIPTION OF THE DRAWINGS IN THE DRAWINGS FIG. 1 is alongitudinal sectional view of a partly completed petroleum wellutilizing equipment of the present invention;

FIG. 2 is a longitudinal sectional view of the well at a later stagewherein steps toward temporary abandonment of the well have beeninitiated;

FIG. 3 is a longitudinal sectional view of the well showing a furtherstep in temporary abandonment;

FIG. 4 shows the well in longitudinal section after temporaryabandonment, with initial steps toward reconnection with the well;

FIG. 5- is a fragmentary longitudinal sectional view of the well showingretrieval of the dutchman of the spline assembly using a spear and stopcollar; and

FIG. 6 shows the well in longitudinal section following reestablishmentof connection with the well, at a stage where the well is ready fornormal completion.

GENERAL DESCRIPTION OF THE WELL For the purpose of most efficientexplanation of the invention to persons skilled in the art, a typicalcasing program will be described in this section. It should be kept inmind, however, that this is but one typical manner in which theprinciples of the invention may be efficiently put to work. Use of theinvention in other programs will be apparent to those skilled in the artfrom the following discussion.

In the example, the casing program includes use of:

30 inch O.D. conductor pipe to 300 feet,

20 inch O.D. outer casing to 500 feet,

13 inch O.D. next inner casing to 4,000 feet,

9 inch O.D. next inner casing to 9,000 feet,

and 7 inch O.D. liner to total depth.

Also in this example, the distance from the rotary table to the waterline is 40 feet and the distance from the rotary table to the mud lineis feet. In other words, the well is being drilled in water 75 feetdeep. The system described, in the presently preferred embodiment,provides for temporary abandonment of the well at the mud line withprovision for tying back to the surface for production.

As initial steps in drilling the well 10, the rig is positioned over thesite and the conductor pipe 12 (FIG. 2) is driven into the bottom untilsuccessive blows no longer result in increased penetration. Thisconventional technique is termed driving until refusal and is normallystated in terms of number of blows needed to increase penetration by 1foot. In the present instance, a refusal at 350 blows/foot might, forinstance, be achieved after 185 feet of conductor pipe had been forcedinto the subsea earth, leaving I additional feet of conductor pipeextending from the mud line up to the rotary. At this point about feetof the upper end of the conductor pipe can be cut off so that thecut-off conductor pipe will terminate about 20 feet above the water lineand about 20 feet below the rotary.

Next, well drilling is begun through the conductor pipe 12 to e.g. 500feet below the rotary at a diameter of 26 inches. The 20 inch casing 14is then run with conventional centralizers 15 to centralize the 20 inchcasing with respect to the 30 inch conductor pipe and the hole, tofacilitate cementing, and casing cutting during temporary abandonment.In this example the annulus 16 between the hole and the 20 inch casingand between the 30 inch conductor pipe and the 20 inch casing iscemented to the surface (i.e. until cement 18 overflows from the cut-offupper end of the 30 inch conductor pipe).

When the cement 18 has set, the 20 inch casing 14 may be cut off abovewhere it emerges from the upper end of the 30 inch conductor pipe and a20 inch casing head and 20 inch blow-out preventor may be temporarilyinstalled to provide for well control during the next drilling step.

In the next step, the well is drilled to 4,000 feet at a diameter of 179% inches through the 20 inch equipment. Then the 13 casing string 22 isrun. This casing string incorporates tie-back provision equipment 24(FIG. 1) which will be described in further detail below.

It is important when practicing the invention to predetermine thelocation of the equipment 24, so that upon running the 13 inch casingstring 22 into the well the equipment 24 will be near the mud line. Itis expected that operators will record the actual positioning for lateruse during temporary abandonment and tie-back. Centralizers 25 are shownprovided on the string 22 above and below the equipment 24.

After the 13 inch casing string 22 is run, the annulus 26 between thecasing string 22 and the hole and between the casing string 22 and the20 inch casing string 14 is cemented to the surface. Tension ismaintained on the upper end of the casing string 22 until the cement 28has set. (Tension setting is a conventional practice.)

In this particular example, the next step involves cutting of the 13 asinch string above where it emerges from the 20 inch casing string,removal of the 20 inch casing head and 20 inch B.O.P. and installationof a 13 inch casing head 32 on the upper end of the 13 inch casingstring with support being transferred to the upper end of the 20 inchcasing 14 via a 20 X 13 X1 95 inches split base plate 34. The base plate34 is circumferentially welded to the head at 36. Associated blowoutpreventer equipment 38 is installed on the head 32 and conventionallytested.

(The decision to use a first, larger diameter casing head and anassociated blow-out preventer when drilling for the surface casing, thento replace this with a smaller diameter casing head and associatedblow-out preventers, is one based on pressure ratings of the equipmentand expected pressures to be encountered. There are instances where itis possible to use one set of larger diameter head and control equipmentthroughout the drilling stages, or such equipment with additionalequipment being installed within or upon the larger diameter firstcasing head.)

As a next step, the well is drilled through the 13 as inch equipment toa depth of e.g. 9,000 feet at a diameter of 12 V inches for receipt ofthe 9 inch O.D. casing string 40 which is then made up and run.

While maintaining the 9 as inch casing string 40 in tension, the annulus46 between the casing 40 and the hole and between the casing 40 and the13 inch casing is cemented then circulated free of cement down to thelevel below the disconnectible joint 48 of the equipment 44. Thetie-back equipment 44 of the 9 if: inch string is located about 30 feetbelow the tie-back equipment 24 of the l3 inch string.

Using conventional equipment and techniques, after the cement 50 hasset, the 9 '56 inch casing may be hung in the casing head 32 using ahanger 52. Then, after actuation of the hanger and testing, the blow-outpreventers may be removed, a casing bonnet, a tubing head, and yetsmaller diameter blow-out preventers installed and tested, in thatorder.

The hole is then drilled to total depth through the smaller diameter (eg10 inch) blow-out preventers and a 7 inch liner 54 run into the wellwithin the 9 as inch casing string and set at 56 with a liner hanger.

The well is then ready for perforation at the level(s) from whichproduction of desired fluids seems promising. Testing of the productionpossibilities can then be conducted in the usual fashion.

If the well proves to be not worth producing from, it may be permanentlyabandoned after recovering all of the equipment from it as is feasible.In the present instance, this can be done by setting cement plugs at theappropriate depths removing the surface well head equipment, moving therig ofi location, attaching salvage lines to the conductor pipe, to theassembly 24 and to the assembly 44 and then shooting ofi the casing at alevel below the equipment 44.

However, if the well looks like it could be of production interest, butis to be temporarily abandoned pending the drilling of additional wells,the tie-backsystem 24 of the present invention comes into play.

DETAILS OF THE TIE-BACK SYSTEM 24 With reference to FIG. 1, the tie-backsystem includes a plurality of interconnected tubular parts, a basic onebeing the tie-back collar 70 which at its lower end threadably connectswith the casing string 22 in which the system 24 is interposed. Theupper end of the system 24 is integrated with the casing string 22 via asub 72 with a threaded box 74. By preference, the collar 70 and sub 72are not made integrally, so that the total length of the system 24, andin particular of the central section 76 thereof can be made of variouslengths in accordance with customer requirements. As will be apparent,this mode also allows reuse of the upper portion of the housing of thesystem. The central section 76 of the housing of the system is showncomprising a nipple of casing pipe, for instance, 8 feet long andexteriorly threaded at both ends. An internally threaded collar 78connects the collar 70 and central section 76; an internally threadedcollar 80 connects the sub 72 and the central section 76.

The bore 82 of the tie-back collar 70 is generally cylindrical,particularly at 84 near its upper end 86 and at 88 below the band ofinternal threading 90 in the bore. The threading 90 is preferablysupplied as Acme threads. Somewhat below the band of threading 90, thebore cylindrical surface 88 is interrupted by a circumferentiallyextending, upwardly facing shoulder 92.

The bore 94 of the sub 72, intermediate the axial extent of the sub 72,is radially enlarged in a sense to produce a downwardly facing shoulder96 and a bore portion 98 of larger diameter from the shoulder 96 to thelower extent of the sub 72.

Thus, the housing 100 of the equipment 24 includes the sub 72, thecollar 80, the central section 76, the collar 78 and the tie-back collar70.

Within the housing 100 is shown received a tubular protector sleeve 102and a tubular cementing sleeve 104. The upper end region of thecementing sleeve is received in the enlarged portion 98 of the sub 72bore, with the cementing sleeve 104 upper end 106 beingcircumferentially welded to the shoulder 96 at 108.

The tubular protector sleeve 102 has a lower end portion received in thebore of the tie-back collar 70 with a lower end 110 seated on theshoulder 92. At raised circumferential bands, the exterior of the sleeve102 is circumferentially grooved at two axially spaced levels facing thetie-back collar bore portion 88 and at twoaxially spaced levels facingthe tieback collar bore portion 84, to receive resilient, annularsealing rings 112 and 114 for sealing with the portions 88 and 84.

The cementing sleeve 104, below its emergence from the boreof the sub 72is provided with a threaded lateral opening 116 which is stopped with athreaded plug 118. The protector sleeve 102, between the. two sets ofsealing rings 112 and 114 is similarly provided with a threaded lateralopening 120 which is stopped with a threaded plug 122.

It should now be noticed that the lower end region of the cementingsleeve 104 is received in the upper end portion of the bore of theprotector sleeve 102. The bore of the protector sleeve 102 is generallycylindrical, but in the upper end region thereof, it is radiallyenlarged to provide an upwardly facing shoulder 126. Thereabove for ashort distance, vertical spline grooves 128 are cut on the bore. Abovethe grooves 128, the bore of the protector sleeve 102 is cylindricallyenlarged in the region 127 to the diameter of the root circle of thegrooves 128. The lower end of the cementing sleeve 104 is shownexteriorly notched to provide vertical spline fins 130 extending up theexterior of the cementing sleeve a short distance. Above the upperextents of the spline fins 130, the cementing sleeve iscircumferentially grooved to receive a resilient sealing ring 132 whichsealingly engages the smooth portion 127 of the bore of the protectorsleeve 102. When assembled as shown, the lower ends of the fins 130enter the upper ends of the grooves 128, thus interdigitating thespline. However, since the lower end of the cementing sleeve still liesabove the shoulder 126 of the protector sleeve, the spline portions aredesigned for greater interpenetration at a later stage (which will belater discussed in connection with FIG. 3).

The purpose of the spline 128/130 is to lock the protector sleeveagainst rotation (because of the fixation of the cementing sleeve to thesub 72 at 108) during drilling and to allow a lower portion of thecementing sleeve to drop down a few inches and get out of the way ascasing cutting steps are begun for temporary abandonment of the well(FIG. 3).

In most instances, the entire assembly 24 as described including thehousing 100, the protector sleeve 102 and the cementing sleeve 104 canbe made up in a manufacturing plant and shipped as an assembled unit forinsertion in a particular size casing string, in the instance shown a 13inch O.D. casing string. The assembly bore 136, principally comprisingthe inwardly exposed parts of the bores of the sub 72, the cementingsleeve 104, the protector sleeve 102 and the tie-back col- I lar 70, hasthe same diameter as the bore of the casing of the casing string 22 inwhich it is interposed.

During assembly, the part of the bore of the tie-back collar 70 whichwill be covered by the protector sleeve is hand packed with heavy grease140. The resilient sealing rings at each end of the protector sleevecontain this body of grease between them. The pipe plug 122 is removedduring assembly to allow excess grease to bleed from the containedspace. After assembly the plug 122 is reinstalled.

The main purpose of the threaded plug 118 is to allow fluid pressuretesting of the threaded joints 142, 144, 146 and 148 andthe weld 108after assembly. During this testing, using a test fluid under pressureadmitted from within the cementing sleeve through the opening 116, theseal at 132 prevents escape of the test fluid into the bore of the 13inch casing string 22. After testing, the test fluid is drained out theopening 116 and the plug 118 is reinstalled.

TEMPORARY ABANDONMENT OF THE WELL With reference to FIG. 2, if the wellis to be temporarily abandoned, communication between subterraneanpressure and the surface is interrupted, eg by installing a wirelinebridge plug 150 above the uppermost perforated interval or abovethe 7inch liner 54 liner hanger 56. Sufficient cement 152 is spotted on topof the bridge plug 150 to keep it in place. In recommended practice fordeep wells, a second cast iron bridge plug 154 may be set at about3,000-feet down from the drilling platform. Then the blow-out preventerstack may be disassembled from the casing head 32and buoys attached tothe conductor pipe via buoy lines 156 secured near the mud line.

Next the 9 inch casing maybe cut at a level below where it is hung inthe head 32. During this stage, the tubing head preferably remains inplace on the casing head bonnet on the casing head 32 to prevent anupward jump of the casing hanger and bonnet when the 9 inch casing isseparated.- After the casing is cut, the hanger, bonnet and tubing headmay be removed with the axially short, cut-off upper end of the 9 inchcasing. A spear 158 can then be used to remove the tie-back sub of theequipment 44 and the 9 "96 inch dutchman (i.e. that part of the 9 "95inch casing lying between the cut and the tie-back sub of the assembly44).

However, as an alternative to cutting the 9 inch casing, if the cementlevel holding the 9 inch casing will allow the casing to stretch, thetubing head and casing bonnet may be removed and the hanger for the 9 5%inch casing spot welded to that casing. A 9 inch casing spear 158 canthen be used to pick up and rotate the 9 inch casing to the right toback the tie-back sub of the equipment 44 out of the tie-back collar ofthe equipment 44. This (using the equipment of the abovementioned Pittset al patent) will require about 14 turns to release the sub. Thus, thehanger, 9 56 inch casing between the hanger and the tie-back sub, andthe 9 inch tie-back sub may be withdrawn from the well as a unit.

Regardless of which way the inner string is disconnected down to thelevel of its tie-back means, the next step of the method disclosedherein is severing of the remaining outer strings and cement annuli at alevelintermediate the axial extent of the system 24.

As noted hereinabove, recording of the level of the system 24 when it isinstalled is important. At the present stage, a multi-string casingcutter 160 (an acceptable one is manufactured by Brown Oil Tools, Inc.of Houston) is lowered in the bore of the 13 inch casing string 22. Whenthe cutter 160 is located within the equipment 24, with the blades 162thereof radially adjacent the cementing sleeve as detected by aconventional collar locator of the cutter and as confirmed by datapreviously recorded as to the level of the apparatus 24, the blades 162of the cutter 160 are actuated to successively cut through the cementingsleeve 104, the housing 100, central section 76, cement in the annulusbetween the 13 and 20 inch casing strings, the 20 inch casing string,the cement in the annulus between the 20 inch casing string and 30 inchconductor pipe, and through the 30 inch conductor pipe. It should herebe noted that in the preferred embodiment as shown, as soon as thecementing sleeve has been cut through, its lower portion (dutchman)below the cut, drops down a few inches further interdigitating thespline 128, 130 the lower end of the cementing sleeve dutchman coming torest on the shoulder 126 of the protector sleeve. Thus, the splineprevents rotation of the cut-ofl lower part of the cementing sleeve andallows this dutchman to drop down out of the way of the cutter bladeswhich then expand to begin cutting the nipple 76. Otherwise, thedutchman could rotate with the cutter causing malfunctioning, cocking ofthe dutchman or damage to other parts. Everything above the cut may thenbe hauled to the surface. It is most convenient to further cut thiscomposite of cement and casings into 15-20 foot sections as it is hauledup.

Then a buoy 166 may be secured to the buoy lines and an abandonment cap168 run down on drill pipe and placed over the cut-ofl upper end 170 ofthe well. It is recommended that this cap 168 have a fishing neck 172welded in its center and lift pad eyes 174 provided at its edges. Thecap is shown provided with a recommended 200 feet or so of junk drillpipe 176 secured to it and hanging from it into the well from thefishing neck to act as a stinger for stabbing (FIG. 4) and to provideadditional weight and stability for the cap 168.

To provide for the possibility that the buoy may become lost during theperiod that the well is temporarily abandoned, it is preferred that asonic pinger locating device (commercially available) be mounted on thecap.

REESTABLISHMENT OF COMMUNICATION WITH THE TEMPORARILY ABANDONED WELLWith further reference to FIG. 4, when reestablishment of communicationwith the temporarily abandoned well is desired, the buoy is removed, anovershot 180 is lowered on drill pipe 182 and, with diver assistance ifneeded, stabbed onto the neck 172 of the abandonment cap 168. The cap isthen withdrawn to the surface with the drill pipe 182.

Next a 13 as inch spear 184 provided with a stop collar 186 is run intothe remaining lower part of the assembly 24 and engaged with theprotector sleeve 102. (The stop collar 186 is used for accuratelyvertically positioning the spear based on knowledge of the length of theupper part of the cementing sleeve retrieved when the well wastemporarily abandoned.) The spear is recovered to the surface, bringingwith it the dutchman of the cementing sleeve 104 and the protectorsleeve 102 with adherent grease 140. The grease has served to preventmud and other fluids from clogging or corroding the space between thecementing sleeve and the tie-back collar.

Retrieval of the cementing sleeve dutchman and the protector sleeveexposes the cylindrical surfaces and the acme threads of the bore of thetie-back collar so that a tie-back sub may be connected to the tie-backcollar.

A tie-back sub 190 is made up on the lower end of a riser 192 of 13 inchcasing and lowered to the upper end of the cut-off well. The sub 190 isprovided with external acme threading corresponding to that of thetie-back collar 70. Using diver assistance if needed, the 13 if; inchtie-back sub 190 is stabbed into the 13 inch tie-back collar and theriser rotated slowly (e.g. 14 turns using hand tongs) until the threadsare made up with desired torque. If operations or foreign matter havesomehow damaged the internal threading in the bore of the 13 inchtie-back collar, a stab-in type tieback sub e.g. as described in theaforementioned U. S. Pat. of Quebe et al No. 3,400,950 may besubstituted for the sub 190.

Then a casing head 194 may be installed on the upper end of the l3 asinch riser 192 and a conventional pressure test conducted to determinethat the 13 inch casing string has been tied-back into with integrity.When this has been established, successive steps may include:

Running a 9 56 inch casing riser 196 with a tie-back sub 198 for tyinginto the equipment 44 in accordance with Pitts et a1, aforementioned;

Grouting the 13 X9 55 inch casing annulus 200 with cement 202 to thesurface, e.g. using a small diameter grouting string lowered into theannulus and gradually raised during the cementing;

Hanging the 9 as inch casing with respect to the head 194 using a hanger204, then installing a bonnet 206 and tubing head 208 (aforementionedComposite Catalog, pages 2116 and 2117);

Installing a blow-out preventer stack 210; then going into the well witha bit 212 and drilling out the cast iron bridge plugs.

The well is then ready to be conventionally completed, e.g. withpackers, tubing, a tubing head bonnet and the associated valving andcontrol devices of a Christmas tree.

Departure from the details set forth above to explain the principles ofthe invention is possible. However, it is believed that those skilled inthe art will appreciate the comprehensiveness of the above discussionand will be better enabled by it to understand how the invention may beeffectively utilized.

In its essence, the invention provides ways and means for temporarilyabandoning and typing back into the casing string of a well casing suingwhich lies between a fully cemented annulus (between it and an outercasing) and a partly cemented or uncemented annulus (between it and aninner casing).

I claim:

1. A petroleum well casing tie-back system comprising: a tubular housinghaving an upper end and a lower end, securement means on said housingupper and lower ends for interposing said housing in a casing string ofparticular inner and outer diameter;

said housing having means defining an internal throughbore; means onsaid housing in said throughbore intermediate said upper and lower endsof said housing defining a band of cooperative securement elements forsubsequent securing reception of a tubular tie-back sub; tubular sleevemeans coaxially received in said throughbore, said sleeve meansextending axially over said band of cooperative securement elements;securement means on said sleeve means and on said housing securing saidsleeve means against rotation with respect to said housing, said sleevemeans having a throughbore of a diameter at least as great as saidparticular inner diameter whereby a petroleum well may be furtherdrilled through said system while said sleeve means protects said bandof cooperative elements against wear damage thereto; at least part ofsaid tubular sleeve means being axially retractable from extendingaxially over said band of cooperative securement elements for exposingthe cooperative securement elements for said subsequent securingreception of a tubular tie-back sub; the housing comprising a sub, anintermediate tubular section having an upper end and a lower end and atie-back collar having an upper end; said band of cooperative securementelements being provided on said tie-back collar; means connecting thesub to the upper end of the intermediate tubular section, meansconnecting the upper end of the tieback collar to the lower end of theintermediate tubular section; said intermediate tubular section beingadapted to be severed in a central portion thereof to expose saidtubular sleeve means for axial retraction; said tubular sleeve meanscomprising an upper, cementing sleeve and a lower, protector sleeve eachhaving a throughbore defining in composite the throughbore of saidtubular sleeve means; a lower portion of said cementing sleeve beingreceived in an upper portion of the throughbore of said protectorsleeve; means defining an upwardly facing shoulder on said protectorsleeve in the throughbore thereof, said shoulder normally being axiallyspaced below and in line with the lower extent of said cementing sleeve;connecting means between the upper end of said cementing sleeve and saidhousing fixedly, connecting the upper end of said cementing sleeve tosaid housing above said central portion; cooperating spline meansextending vertically on the lower end of said cementing sleeve and onsaid protector sleeve in the throughbore thereof above said shoulder;said cementing sleeve normally having a central portion thereof disposedradially adjacent said central portion of said housing and adapted to besevered immediately prior to severing of said housing central portion,whereby a dutchman of said cementing sleeve created by the severing ofsaid cementing sleeve at said central section thereof may drop out ofthe way and land on said shoulder; means defining an internal shoulderon said housing below said central section thereof and means defining anexternal shoulder on said protector sleeve adapted to rest upon andreceive support from said internal shoulder to support said protectorsleeve and the dutchman of said cementing sleeve in said housing belowsaid central section following severing of said cementing sleeve andsaid housing at their respective central sections.

2. A petroleum well casing tie-back system comprising: a tubular housinghaving an upper end and a lower end, securement means on said housingupper and lower ends for interposing said housing in a casing string ofparticular inner and outer diameter;

said housing having means defining an internal throughbore; means onsaid housing in said throughbore intermediate said upper and lower endsof said housing defining a band of cooperative securement elements forsubsequent securing reception of a tubular tie-back sub; tubular sleevemeans coaxially received in said throughbore, said sleeve meansextending axially over said band of cooperative securement elements;securement means on said sleeve means and on said housing securing saidsleeve means against rotation with respect to said housing, said sleevemeans having a throughbore of a diameter at least as great as saidparticular inner diameter whereby a petroleum well may be furtherdrilled through said system while said sleeve means protects said bandof cooperative elements against wear damage thereto; at least part ofsaid tubular sleeve means being axially retractable from extendingaxially over said band of cooperative securement elements for exposingthe cooperative securement elements for said subsequent securingreception of a tubular tie-back sub; further comprising circumferentialsealing ring means provided between said housing and said tubular sleevemeans both above and below said band of cooperative securement elements;an extensive body of fluid packing material filling axially between thesealing ring means, and radially between the housing and the tubularsleeve means.

3. The system of claim 2 wherein the band of cooperative securementelements comprise helical threading.

4. The system of claim 2 wherein the housing comprises a sub, anintermediate tubular section having an upper end and a lower end and atie-back collar having an upper end; said band of cooperative securementelements being provided on said tie-back collar; means connecting thesub to the upper end of the intermediate tubular section, meansconnecting the upper end of the tie-back collar to the lower end of theintermediate tubular section; said intermediate tubular section beingadapted to be severed in a central portion thereof to expose saidtubular sleeve means for axial retraction.

5. The petroleum well casing tie-back system of claim wherein thepacking consists of heavy grease; said tubular sleeve means beingprovided with means defining a threaded opening therethrough normallylying axially between said sealing ring means, and a threaded plugnormally stopping said opening, said plug being removable for bleedingof said grease during assembly of said system.

6. A method for temporarily abandoning a petroleum well having an outerstring of casing comprising:

providing the well with an inner, concentric string of casing having aband of internal tie-back sub securement means in the bore thereof forsubsequent receptive securement of a tie-back sub and a non-rotatablesleeve covering the securement means;

cementing the annulus between the inner and outer casing strings up pastthe level of said securement means; allowing the cement to set;

severing the inner and outer strings of casing above said securementmeans leaving said sleeve covering said securement means; and

capping the well.

7. A method for temporarily abandoning, then tying back into, apetroleum well having an outer string of casing comprising:

providing the well with an inner, concentric string of casing having aband of internal tie-back sub securement means in the bore thereof forsubsequent receptive securement of a tie-back sub and a non-rotatablesleeve covering the securement means;

cementing the annulus between the inner and outer casing strings up pastthe level of said securement means; allowing the cement to set;

severing the inner and outer strings of easing above said securementmeans leaving said sleeve covering said securement means;

withdrawing the severed elements; and

Slapping the well for temporary abandonment;

sequently, on capping the well; withdrawing said sleeve to expose saidsecurement means;

making up a casing riser with a tie-back sub on the lower end thereof;

lowering said riser toward the well;

stabbing said tie-back sub into the well and securely engaging the subwith said securement means to reestablish communication with the innercasing string of the well.

1. A petroleum well casing tie-back system comprising: a tubular housinghaving an upper end and a lower end, securement means on said housingupper and lower ends for interposing said housing in a casing string ofparticular inner and outer diameter; said housing having means definingan internal throughbore; means on said housing in said throughboreintermediate said upper and lower ends of said housing defining a bandof cooperative securement elements for subsequent securing reception ofa tubular tie-back sub; tubular sleeve means coaxially received in saidthroughbore, said sleeve means extending axially over said band ofcooperative securement elements; securement means on said sleeve meansand on said housing securing said sleeve means against rotation withrespect to said housing, said sleeve means having a throughbore of adiameter at least as great as said particular inner diameter whereby apetroleum well may be further drilleD through said system while saidsleeve means protects said band of cooperative elements against weardamage thereto; at least part of said tubular sleeve means being axiallyretractable from extending axially over said band of cooperativesecurement elements for exposing the cooperative securement elements forsaid subsequent securing reception of a tubular tie-back sub; thehousing comprising a sub, an intermediate tubular section having anupper end and a lower end and a tie-back collar having an upper end;said band of cooperative securement elements being provided on saidtie-back collar; means connecting the sub to the upper end of theintermediate tubular section, means connecting the upper end of thetie-back collar to the lower end of the intermediate tubular section;said intermediate tubular section being adapted to be severed in acentral portion thereof to expose said tubular sleeve means for axialretraction; said tubular sleeve means comprising an upper, cementingsleeve and a lower, protector sleeve each having a throughbore definingin composite the throughbore of said tubular sleeve means; a lowerportion of said cementing sleeve being received in an upper portion ofthe throughbore of said protector sleeve; means defining an upwardlyfacing shoulder on said protector sleeve in the throughbore thereof,said shoulder normally being axially spaced below and in line with thelower extent of said cementing sleeve; connecting means between theupper end of said cementing sleeve and said housing fixedly, connectingthe upper end of said cementing sleeve to said housing above saidcentral portion; cooperating spline means extending vertically on thelower end of said cementing sleeve and on said protector sleeve in thethroughbore thereof above said shoulder; said cementing sleeve normallyhaving a central portion thereof disposed radially adjacent said centralportion of said housing and adapted to be severed immediately prior tosevering of said housing central portion, whereby a dutchman of saidcementing sleeve created by the severing of said cementing sleeve atsaid central section thereof may drop out of the way and land on saidshoulder; means defining an internal shoulder on said housing below saidcentral section thereof and means defining an external shoulder on saidprotector sleeve adapted to rest upon and receive support from saidinternal shoulder to support said protector sleeve and the dutchman ofsaid cementing sleeve in said housing below said central sectionfollowing severing of said cementing sleeve and said housing at theirrespective central sections.
 2. A petroleum well casing tie-back systemcomprising: a tubular housing having an upper end and a lower end,securement means on said housing upper and lower ends for interposingsaid housing in a casing string of particular inner and outer diameter;said housing having means defining an internal throughbore; means onsaid housing in said throughbore intermediate said upper and lower endsof said housing defining a band of cooperative securement elements forsubsequent securing reception of a tubular tie-back sub; tubular sleevemeans coaxially received in said throughbore, said sleeve meansextending axially over said band of cooperative securement elements;securement means on said sleeve means and on said housing securing saidsleeve means against rotation with respect to said housing, said sleevemeans having a throughbore of a diameter at least as great as saidparticular inner diameter whereby a petroleum well may be furtherdrilled through said system while said sleeve means protects said bandof cooperative elements against wear damage thereto; at least part ofsaid tubular sleeve means being axially retractable from extendingaxially over said band of cooperative securement elements for exposingthe cooperative securement elements for said subsequent securingreception of a tubular tie-back sub; further comprising circumferentialsealing ring means provided between said housing and sAid tubular sleevemeans both above and below said band of cooperative securement elements;an extensive body of fluid packing material filling axially between thesealing ring means, and radially between the housing and the tubularsleeve means.
 3. The system of claim 2 wherein the band of cooperativesecurement elements comprise helical threading.
 4. The system of claim 2wherein the housing comprises a sub, an intermediate tubular sectionhaving an upper end and a lower end and a tie-back collar having anupper end; said band of cooperative securement elements being providedon said tie-back collar; means connecting the sub to the upper end ofthe intermediate tubular section, means connecting the upper end of thetie-back collar to the lower end of the intermediate tubular section;said intermediate tubular section being adapted to be severed in acentral portion thereof to expose said tubular sleeve means for axialretraction.
 5. The petroleum well casing tie-back system of claim 5wherein the packing consists of heavy grease; said tubular sleeve meansbeing provided with means defining a threaded opening therethroughnormally lying axially between said sealing ring means, and a threadedplug normally stopping said opening, said plug being removable forbleeding of said grease during assembly of said system.
 6. A method fortemporarily abandoning a petroleum well having an outer string of casingcomprising: providing the well with an inner, concentric string ofcasing having a band of internal tie-back sub securement means in thebore thereof for subsequent receptive securement of a tie-back sub and anon-rotatable sleeve covering the securement means; cementing theannulus between the inner and outer casing strings up past the level ofsaid securement means; allowing the cement to set; severing the innerand outer strings of casing above said securement means leaving saidsleeve covering said securement means; and capping the well.
 7. A methodfor temporarily abandoning, then tying back into, a petroleum wellhaving an outer string of casing comprising: providing the well with aninner, concentric string of casing having a band of internal tie-backsub securement means in the bore thereof for subsequent receptivesecurement of a tie-back sub and a non-rotatable sleeve covering thesecurement means; cementing the annulus between the inner and outercasing strings up past the level of said securement means; allowing thecement to set; severing the inner and outer strings of casing above saidsecurement means leaving said sleeve covering said securement means;withdrawing the severed elements; and capping the well for temporaryabandonment; subsequently, on capping the well; withdrawing said sleeveto expose said securement means; making up a casing riser with atie-back sub on the lower end thereof; lowering said riser toward thewell; stabbing said tie-back sub into the well and securely engaging thesub with said securement means to reestablish communication with theinner casing string of the well.